Method and apparatus for optimizing the operation of a turbine system under flexible loads

ABSTRACT

A gas turbine system includes a compressor protection subsystem; a hibernation mode subsystem; and a control subsystem that controls the compressor subsystem and the hibernation subsystem. At partial loads on the turbine system, the compressor protection subsystem maintains an air flow through a compressor at an airflow coefficient for the partial load above a minimum flow rate coefficient where aeromechanical stresses occur in the compressor. The air fuel ratio in a combustor is maintained where exhaust gas emission components from the turbine are maintained below a predetermined component emission level while operating at partial loads.

TECHNICAL FIELD

The present invention relates to gas turbine systems, and moreparticularly to apparatus and methods for optimizing the operation of aturbine system under flexible loads.

BACKGROUND

As a result of continuing global population and income growth,electricity demand continues to increase worldwide. Electricity gridsare required to adjust to large somewhat unpredictable swings in demandas well as the planned and unplanned changes in production capacity.Additionally, alternative sources such as wind and solar generated powerare growing in importance and these sources have an impact in the waythat power is generated to meet the demand.

Electricity demand is chaotic. Demand may vary on a daily, monthly,seasonal and yearly cycles. For example, a typical residential dailydemand profile on a hot day may show a minimum in the early morninghours, and a maximum in the early evening hours. Commercial demand onthe same day may show a minimum in the early evening hours and a maximumaround the middle of the day. Weather and season of the year also impactdemand. The peak demand may in some cases be double the minimum demand.

Because electricity generated by power companies cannot be efficientlystored, electric utilities have traditionally generated power with acombination of different approaches to production. For example, largenuclear or coal fired plants may be used for generating a minimum amountof power (baseload). Baseload power plants typically operatecontinuously at maximum output.

During times of peak demand (peak load) power companies may use simplecycle gas turbines for generating power. Gas turbines are desirable forsupplying the additional capacity required during peak loads because oftheir ability to start up quickly, producing electrical power in 10 to30 minutes. Gas turbines used to generate power during periods of peakloads may be shut down for portions of a day when the demand for poweris low. The period of operation of the gas turbines may vary inaccordance with the demand.

Some utilities also operate load following plants that run during theday to supply power during periods of intermediate demand. Combinedcycle gas turbine systems are sometimes used for as load followingplants. COMBINED CYCLE GAS TURBINE systems typically include a heatrecovery steam generator coupled to the exhaust of the gas turbine.combined cycle gas turbine systems may adjust their power output asdemand fluctuates throughout the day. combined cycle gas turbine systemsare typically in between base load power plants and peaking plants (e.g.gas turbines used to provide peak power) in efficiency, speed of startupand shutdown, and capacity.

To meet the increased demands and address environmental concerns, manyutilities are using sources of renewable energy, such as wind and solarpower to meet intermediate and peaking loads. These sources addadditional variability to the electricity demand because of theirintermittent generation capacity. For example, power output of a solarelectricity generation plant varies depending on the cloud cover and,similarly wind power output will vary depending on wind speed.

Gas turbines have a number of advantages as sources of power for peakloads. Gas turbines are efficient, have a relatively low installed cost,have a relatively fast start up, and shut down and low emissions. Thestartup sequence of a gas turbine begins with energizing a starter. Whenthe RPM of the turbine reaches a light up RPM the ignition systems areenergized and fuel is provided to the combustor. Upon combustion, thefuel flow is increased while maintaining temperatures below establishedtemperature limits. Fuel flow is then controlled to achieve smoothacceleration until idle speed is reached.

A gas turbine may be operated at base load, peak load, and loads belowthe base load. The gas turbine baseload is the load that optimizes poweroutput, and hot gas path parts life. ANSI B133.6 Ratings and Performancedefines base load as operation at 8,000 hours per year with 800 hoursper start. It also defines peak load as operation at 1250 hours per yearwith five hours per start. The peak load of a gas turbine is a load thatmaximizes power output, frequently at the expense of efficiency, partslife and inspection intervals. Gas turbines may be operated at partialor low loads in order to be able to quickly ramp up to higher outputwhen demand for power increases. There are advantages and disadvantagesin operating a gas turbine at partial loads. One advantage is to reducethe plant maintenance costs incurred during start-ups and shut-downs.However, operation at low loads results in lower operating efficienciesand higher operating costs.

Work from a gas turbine varies as a function of mass flow, heat energyin the combusted gas, and temperature differential across the turbine.These factors may be affected by ambient conditions, fuels, inlet andexhaust losses, fuel heating, diluent injection, air extraction, inletcooling and steam and water injection. For example, changes in ambientconditions (pressure, temperature and humidity) affect the densityand/or mass flow of the air intake to the compressor and consequentlygas turbine performance. The mass flow is in turn a function ofcompressor airflow and fuel flow.

Compliance with emission standards is also a major constraint in theoperation of gas turbines. Most gas turbines combust low sulfur and lowash fuels. Consequently, the major pollutants emitted from gas turbinesare nitrogen oxides (NO and NO2, collectively referred to as NOx),carbon monoxide (CO), and volatile organic compounds (VOC). NOx and COare considered the primary emissions of significance when combustingnatural gas in gas turbines. Emissions from gas turbines varysignificantly as a function of ambient temperature, load, and pollutantconcentration. Below 50% load, emission concentrations may increase.This is especially true for carbon monoxide (CO). Consequently, there isa limit to the load level at which conventional gas turbine systems maybe operated while still complying with emission standards.

Emission standards applicable to gas turbine operations may vary bycountry and in the United States, in addition to Federal standards,standards may vary from State to State. Regulatory authorities mayimpose various regimes for regulating emissions. For example, an NOxemission limit may be stated as pounds of NOx per unit of output, or perunit of heat input (instantaneous limit). In some cases the standardsmay be formulated as a concentration-based or an output-based emissionstandard. A concentration-based limit may be stated in units of partsper million by volume (ppmv). The output-based emission limit may bestated in units of emissions mass per unit useful recovered energy, orpounds per megawatt-hour. Some plants may be limited on the basis of thenumber of tons of NOx emitted per year or other time period (periodiclimit).

Some power plants have emissions limits and other restrictions when inthe startup mode. Types of startup limits include: (a) pounds per hour,(b) lb/event/CTG and (c) lb/event/power block. A maximum allowablelb/hour limit may be required by the regulatory agency, since it is themost straightforward value to use in an air quality impact assessment.

One of the problems with the operation of gas turbines over wide powerranges is that efficiency, fuel consumption and emissions, specifically,NOx and CO emissions, may be negatively affected. For example, when aplant operator operates a conventional gas turbine at low loads there isa significant decrease in efficiency. Another problem is that thecompressor may be subjected to aeromechanical stresses in the aft stageswhen the gas-fired turbine is operated at lower loads in low ambienttemperature conditions. These stresses occur below the aerodynamicstability limit due to an excitation of an aeromechanical mode which isdriven by an increase in the stage loading parameter. The flow ratecoefficient values at which these stresses are evident are referred toas the turndown restricted zone. Yet another problem with gas turbinesoperating at lower ambient temperatures is that the minimum loadrequired for CO compliance is a function of, among other things, theambient temperature. For example, in some gas turbines, as thetemperature falls below 35 F (1.7 C), the minimum load for CO compliancerises steeply. Yet another problem is that the use of a heat recoverysteam generator in a combined cycle gas turbine systems may imposeadditional constraints on the optimal gas turbine operation atbase-load, part-load and load-ramp operating modes. Yet another problemis that when the gas turbine is operated at extreme low hibernationmodes of approximately 10% load there is the potential of combustor leanblowout (i.e. loss of flame).

BRIEF DESCRIPTION OF THE INVENTION

According to one aspect of the invention, a method for changing thepower output in a gas turbine system is provided. The method of thisaspect includes determining an existing power output and a desired poweroutput. The method also includes measuring existing compressorparameters and combustor parameters; calculating a compressor flow ratecoefficient for the desired power output; and calculating an emissionrate for the desired power output. If the flow rate coefficient for thedesired power output is less than a predetermined turndown limit, thenmethod includes calculating new compressor parameters that result in aflow rate coefficient above the predetermined turndown limit. If thecalculated emission rate is greater than a predetermined emissionslimit, then the method includes calculating new combustor parametersthat result in an emission rate lower than the predetermined emissionslimit. The method also includes changing the power output to the desiredpower output; changing the compressor parameters to the new compressorparameters; and changing the combustor parameters to the new combustorparameters.

According to another aspect of the present invention, a gas turbinesystem is provided. The gas turbine system of this aspect includes acompressor; a combustor; a turbine; a compressor protection subsystem; ahibernation mode subsystem; and a control subsystem that controls thecompressor subsystem and the hibernation subsystem.

According to another aspect of the present invention a method ofextending the turndown range of the gas turbine system is provided. Themethod includes establishing minimum air flow parameters for air flowingthrough the compressor; conveying turbine exhaust from the turbine to amixing assembly at a first flow rate; conveying compressed air from thecompressor to the mixing assembly at a second flow rate; and controllingthe first flow rate and the second flow rate to maintain the compressorairflow above the minimum air flow parameters.

According to another aspect of the present invention a method ofimproving the efficiency of the combined cycle gas turbine at partialload is provided. The method includes maintaining an air flow through acompressor at an airflow coefficient for the partial load above aminimum flow rate coefficient where aeromechanical stresses occur in thecompressor; maintaining an air fuel ratio in a combustor where exhaustgas emission components from the turbine are maintained below apredetermined component emission level; and maintaining an exhaust gastemperature at an inlet of a heat recirculation steam generator below apredetermined maximum inlet temperature.

According to another aspect of the present invention, a system forimproving the efficiency of a combined cycle gas turbine at partialload. The system includes a turndown subsystem; a hibernation subsystem;a combined cycle isotherm subsystem; and a control subsystem thatprovides instructions to the turndown subsystem to maintain in airflowthrough a compressor an inner flow coefficient for the partial load upof a minimum flow rate coefficient where aeromechanical stresses occurin the compressor.

BRIEF DESCRIPTION OF THE DRAWINGS

These and other features, aspects, and advantages of the presentinvention will become better understood when the following detaileddescription is read with reference to the accompanying drawings in whichlike characters represent like parts throughout the drawings, wherein:

FIG. 1 is a block diagram of an embodiment of a gas turbine systemaccording to one embodiment of the present invention.

FIG. 2 is a block diagram illustrating a turndown subsystem according toone embodiment of the present invention.

FIG. 3 is a block diagram illustrating a turndown subsystem according toan alternate embodiment of the present invention.

FIG. 4 is a block diagram illustrating a hibernation mode subsystemaccording to one embodiment of the present invention.

FIG. 5 is a block diagram illustrating a combined cycle isothermsubsystem according to one embodiment of the present invention.

FIG. 6 is a cross sectional view of a fogger component of the combinedcycle isotherm subsystem according to one embodiment of the presentinvention.

FIG. 7 is a longitudinal sectional view of a fogger component of thecombined cycle isotherm subsystem according to one embodiment of thepresent invention.

FIG. 8 is a block diagram illustrating a control subsystem according toone embodiment of the present invention.

FIG. 9 is a block diagram of inputs and outputs of a control subsystemaccording to one embodiment of the present invention.

FIG. 10 is a flow diagram of a method for turning down the power outputin a gas turbine system according to one embodiment of the presentinvention.

FIG. 11 is a flow diagram of a method for turning down the power outputin a gas turbine system according to one embodiment of the presentinvention.

FIG. 12 is a flow diagram of a method for extending the turndown rangeof a gas turbine system according to one embodiment of the presentinvention.

DETAILED DESCRIPTION OF THE INVENTION

FIG. 1 illustrates a high-level schematic of an embodiment of a gasturbine system 1. The gas turbine system 1 includes a conventional gasturbine 3, turndown subsystem 4, and a control subsystem 11. Theturndown subsystem 4 may include a compressor protection subsystem 5, ahibernation mode subsystem 7 and a combined cycle isotherm subsystem 9.

The gas turbine 3 may include a compressor 13, a combustor 15, a turbine17, a generator 18, an inlet guide vane (IGV) subsystem 19 and a heatrecovery steam generator (heat recovery steam generator subsystem 21)subsystem 21. In operation, ambient air 20 is drawn through the IGVsubsystem 19 and enters the compressor 13. The temperature, pressure andrelative humidity of ambient air 20 will obviously vary. For comparativepurposes, the turbine industry has established standard conditions forambient air. The standard conditions are 59° F./15° C., 14.696psia/1.013 bar and 60% relative humidity. The IGV subsystem 19 serves tovary the volumetric flow into the compressor 13. Compressed air from thecompressor 13 enters the combustor 15 where it is mixed with fuel fromfuel input 16 and combusted. Exhaust air from the combustor 15 drivesthe turbine 17 which in turns drives a shaft connected to the generator18. In some systems the exhaust gases are made to flow into an heatrecovery steam generator subsystem 21 which recovers heat from theexhaust gases and drives a steam turbine (not shown) to generateadditional power and/or provide steam to a process such as districtheating. The gas turbine system 1 also includes a compressor bleed line25 and an exhaust gas extraction line 27 coupling the gas turbine 3 tothe turndown subsystem 4. In another embodiment, an exhaust gasextraction line 28 may be provided to bypass turndown subsystem 4, andprovide exhaust gasses directly to gas turbine 3. Compressor bleed line25 and exhaust gas extraction line 27 may also be coupled to thecombined cycle isotherm subsystem 9 where the gasses may be blended withattemperation fluids at combined cycle input 22. The attemperation fluidmay be ambient air, water, steam, any combination thereof, or any otherfluid that can provide the function of regulating the temperature ofgasses in the combined cycle isotherm subsystem 9.

Illustrated in FIG. 2 is one embodiment of the compressor protectionsubsystem 5 (outlined in a double dashed line). The components thatrepresent the compressor protection subsystem 5 are illustrated in solidlines. Other components of the gas turbine system 1 are illustrated asdashed lines. In this embodiment, the compressor bleed line 25 iscoupled to an external duct assembly including an upstream compressorbleed control valve 29, a downstream compressor bleed control valve 31,and a compressor bleed flow sensor 33. Control subsystem 11 controls thecontrol valve 31 which in turn controls the flow rate of the compressedair (Q1). Compressed air is transported to a blending assembly 35, suchas a manifold or eductor where it is blended with exhaust gas andconveyed to the IGV subsystem 19. The exhaust air is provided by anexternal duct assembly coupled to the exhaust gas extraction line 27.The exhaust gas extraction line 27 is provided with an exhaust gasextraction (EGE) flow sensor 39, an EGE control valve 41 and an EGEblock valve 43. The EGE sensor 39 provides data of the flow rate ofexhaust gasses (Q2) to the control subsystem 11. The control subsystem11 provides control signals to the upstream compressor bleed controlvalve 29, the downstream compressor bleed control valve 31, the EGE flowsensor 39 the EGE control valve 41 and the EGE block valve 43. The Acompressor and exhaust may be blended with ambient air at gas turbineinlet system 37.

Illustrated in FIG. 3 is an alternate embodiment of a compressorprotection subsystem 5 where an intermediate stage compressor bleed line45 is connected to an intermediate stage of the compressor 13.Compressed air from the compressor bleed line 25 and the intermediatestage compressor bleed line 45 is mixed through a blending component 46such as a manifold or eductor to create a first blend. The blendedcompressor air is blended with exhaust air from exhaust gas extractionline 27 at blending assembly 35. The second blend may then be blendedwith the ambient air 20 at the gas turbine inlet system 37 and theblended gasses are supplied through the IGV 19 to the compressor 13.

The compressor protection subsystem 5 provides the operator of the gasturbine 3 with the ability to control the performance of the systemthrough continuous control of compressor parameters, such as the stageloading parameters and the flow coefficient of the air passing throughthe compressor. The stage loading parameter is a non-dimensional measureof the work extraction per stage, a high stage loading is desirablebecause it means fewer stages are needed to produce a required workout.The stage loading is limited by the fact that high-stage loading impactsefficiency. The stage loading parameter can be characterized on thebasis of a minimum relative Cm/U (flow coefficient). The flowcoefficient is the ratio of the axial velocity entering to the meaningrotor speed. It has been found that compressors and turbines work mostsatisfactorily if the non-dimensional axial velocity, often called flowcoefficient is in a restricted range. The flow coefficient for a givenstage is a characteristic of the mass flow behavior through the stage.For a given flow coefficient, the stage loading increases with anincrease in blade angle of the compressor blades from the axialdirection.

The control of the compressor parameters enables the plant operator torun the gas turbine at lower loads in varying ambient conditions, suchas cold temperatures, while avoiding the aeromechanical stresses thatconventional gas turbines are subjected to at the lower temperatures.This is accomplished by controlling the inlet temperature of the airentering the compressor and the vane angle of the vanes in the IGVsubsystem 19. The compressor inlet temperature is controlled usingextracted exhaust gas. By controlling the temperature of the blendedgasses supplied through the IGV 19 to the compressor 13 the gas turbine3 is able to operate above the turndown restricted zone in low ambienttemperatures (beyond nominal Cm/U levels) thereby protecting thecompressor 13 when the gas turbine 3 is operating at low loads.Additionally, the hibernation mode subsystem seven enables the operatorof a gas turbine 3 to operate in turn downloads beyond nominal COemission limits.

The customer benefits with extended turndown are increased annualproduction hours (availability, capacity factor) reduction in start-upshut-down cycles (reduced maintenance cost) and significant improvementin operating efficiency at this lower turndown relative to nominal underlow ambient temperatures.

An advantage of the compressor protection subsystem 5 described hereinis that capital and maintenance costs may be reduced by reducing theoverall complexity of the system used to heat the air supplied to thecompressor 13. Another advantage of the compressor protection subsystem5 described herein is that it allows the operator of a gas turbine 3 toimprove the operating efficiency when using low BTU fuel gases such asin an integrated gasification combined-cycle (IGCC) operation.

Illustrated in FIG. 4 is an embodiment of a hibernation mode subsystem7. The hibernation mode subsystem 7 is illustrated within the doubledashed outline, and the components of the hibernation mode subsystem 7are illustrated as solid lines. Other components of the gas turbinesystem 1 are illustrated as dashed lines. In this embodiment, compressedair from the compressor 13 is split at splitter 48 into a portion to bebled into the compressor 13 through an upstream compressor bleed controlvalve 29, a downstream compressor bleed control valve 31, and acompressor bleed flow sensor 33. The portion to be bled into thecompressor is conveyed to the IGV subsystem 19. The compressed air fromthe compressor 13 is also split into a second portion to be overboardedto the exhaust gasses through a compressor air overboarding line 47. Theflow of the air to be overboarded to the exhaust gases is controlled byan over boarding block valve 49, and over boarding control valve 51 andan overboarding flow sensor 53. The overboarding flow sensor 53 providesflow rate data to the control subsystem 11. The control subsystem 11combustor provides control signals to the over boarding block valve 49and the over boarding control valve 51.

The hibernation mode subsystem 7 enables a hibernation mode byoverboarding compressor discharge air to the compressor inlet and to theturbine exhaust, thereby maintaining the desired fuel air ratio (FAR)that supports emissions at a level below the maximum limits. Thehibernation mode subsystem 7 may be integrated with the previouslydescribed compressor protection subsystem 5. This invention also reducesthe customer's operation and maintenance costs associated with operationat very low hours/starts ratio.

The hibernation mode subsystem 7 enables the operator of the gas turbine3 to operate at an extreme low “hibernation mode” level of approximately10% load with the capability to rapidly ramp load up to base load levelto provide for needed spinning capacity. The hibernation mode subsystem7 may also reduce the operation and maintenance costs associated withthe operation of a gas turbine 3 at very low hours/starts ratio. Thehibernation mode subsystem 7 also enables the operator of the gasturbine 3 to operate at an extreme low hibernation mode while stillcomplying with emissions regulations. The hibernation mode subsystem 7illustrated in this embodiment would require no design changes to thegas turbine 3 centerline or combustion systems and may be accomplishedwith minimal additional capital components. The hibernation modesubsystem 7 enables selectable gas turbine 3 turndown beyond nominal CO& NOx emissions limits. Additionally, the hibernation mode subsystem 7establishes a scheme to trim air-fuel ratio and mitigate combustorlean-blow-out.

Illustrated in FIG. 5 is a combined cycle isotherm subsystem 9 which maybe implemented as part of the turndown subsystem 4 in a combined cycleembodiment. In a combined cycle embodiment, high temperature exhaust gasfrom a gas turbine 3 is passed through a heat recovery steam generator21 to produce steam that drives a steam turbine. It is often desirableto uprate the gas turbine 3 to increase output and reduce heat rate,however, the design limits of the heat recovery steam generator 21 canimpose additional constraints on the optimal gas turbine operation atbase-load, part-load and load-ramp operating modes.

The combined cycle isotherm subsystem 9 is illustrated within the doubledashed outline, and the components of the combined cycle isothermsubsystem 9 are illustrated as solid lines. Other components of the gasturbine system 1 are illustrated as dashed lines. In this embodiment,compressed air from the compressor 13 flows through compressor bleedline 25. As previously described, an upstream compressor bleed controlvalve 29 may be disposed on the compressor bleed line 25. Additionally,over boarding block valve 49, over boarding control valve 51, and overboarding flow sensor 53 may be disposed on the compressor air overboarding line 47. Additionally, Safety valve 54 may be disposed on thecompressor air overboarding line 47. The compressed air may be blendedwith the exhaust from the turbine 17 and with attemperation fluid atcombined cycle input 22. The combined compressor air, exhaust andattemperation fluid may flows through an attemperation subsystem 55,where the temperature of the combined gases may be controlled. Thecombined attemperated gases are made to flow into a heat recovery steamgenerator subsystem 21, where additional work may be extracted.

Combined cycle operation requires that the exhaust gases leaving the gasturbine engine be within a specific temperature range. That is theexhaust temperature cannot be too high to avoid degrading the gasturbine exhaust duct and heat recovery steam generator 21 hardware.Further, the temperature should not fall below a certain temperaturevalue to avoid a condition called forced cooling when thermal transientsin steam turbine rotor and casing can degrade the turbine rotor. The twotemperatures limits discussed above are referred to as the upperthreshold isotherm and the lower threshold isotherm respectively.

The attemperation subsystem 55 is an assembly that providesafter-cooling with water foggers for attemperation. The attemperationsubsystem 55 provides an optimized fogger arrangement in the exhaustduct of the gas turbine 3, with one or more fogger injection nozzles 57located in the a duct. Each fogger injection nozzle 57 is provided withcondensate or other working fluid from working fluid input 58 and isshielded upstream by a shaped baffle assembly 59.

Illustrated in FIGS. 6 and 7 is the shaped baffle assembly 59. Baffles61 are strategically placed to optimize the overlapping spray pattern 62to achieve gas temperature uniformity. The attemperation subsystem 55accepts condensate from any pressure zone in the heat recovery steamgenerator subsystem 21 or externally supplied demineralized water as theworking fluid. The fogger flow rate and the condensate source may becontrolled by the control subsystem 10.

The combined cycle isotherm subsystem 9 provides the capability toexternally manage and optimize the exhaust gas temperature entering theheat recovery steam generator 21 by means of aftercooling withattemperating water foggers.

The combined cycle isotherm subsystem 9 partially overcomes some of theconstraints to efficiency and ability to operate at part load that isimposed by inlet gas temperature limits. These constraints can limit theoutput of the gas turbine 3 and overall plant efficiency at all loadpoints. Consequently, the gas turbine 3 may be operated with exhaust gastemperature above the inlet temperature limit of the HRSG 21 during alloperating modes, improving the load ramp rates and exhaust gas heattransfer to the heat recovery steam generator subsystem 21. The combinedcycle isotherm subsystem 9 provides a method to externally manage andoptimize the temperature of the exhaust gas from the gas turbine 3entering the heat recovery steam generator subsystem 21 by means ofafter-cooling with water/steam foggers for attemperation. Additionally,the combined cycle isotherm subsystem 9 provides a fogger nozzle andbaffle arrangement for downstream temperature uniformity and enables gasturbine customer to operate the gas turbine 3 with exhaust gastemperature above the inlet temperature limit of the heat recovery steamgenerator subsystem 21 during any operating mode. Use of the combinedcycle isotherm subsystem 9 also improves the combined cycle gas turbineplant load ramp rate and prevents a mismatch between the gas turbine 3and the heat recovery steam generator subsystem 21 when a gas turbine 3is uprated. Another advantage of the combined cycle isotherm subsystem 9is that it provides a means for adjusting load balance between gasturbine 3 and the combined cycle plant, with maximum steam productionwhen power output is not required. This in turn provides the power plantoperator with flexibility in some applications where additional steam isdesired such as with district heating and on site cogeneration infacilities such as refineries. Other advantages are improvement of theexhaust gas heat transfer to the heat recovery steam generator subsystem21 and the combined cycle gas turbine heat rate under part-loadconditions where the gas turbine 3 is isotherm constrained. Finally, thecombined cycle isotherm subsystem 9 improves emissions profile underextended turndown and the ability to uprate vintage power plants.Additional benefits include increased annual production hours(availability, capacity factor); Reduction in combined cycle gas turbinestart-up shut-down cycles (reduced maintenance cost) with load balancingflexibility and improvement in part-load operating efficiency withcombined cycle gas turbine uprates.

Illustrated in FIG. 8 is a control subsystem 100 used to control thevarious components and processes of the turbine system 1. The controlsubsystem 100 may include a control module 103, typically a digitalcomputer that automates electromechanical processes such as control ofcomponents of the turbine system 10. These components may include theinlet guide vane subsystem 19, the compressor 13, and the combustor 15.For example, the control module 103 may be a General ElectricSPEEDTRONIC™ Gas Turbine Control subsystem, such as is described inRowen, W. I., “SPEEDTRONIC™ Mark V Gas Turbine Control subsystem”,GE-3658D, published by GE Industrial & Power Systems of Schenectady,N.Y. For example, a control subsystem such as described in U.S. Pat. No.6,912,856 entitled “Method and System for Controlling Gas Turbine byAdjusting Target Exhaust Temperature,” by Rex Allen Morgan, et al, whichis hereby incorporated by reference.

The control module 103 includes a central processing unit 105.Associated with the central processing unit 105 may be a memorycomponent 107 an input component 109 and output component 111. Thememory component 107 may include a flash disk card, a random accessmemory card (RAM), a read only memory (ROM), a dynamic random accessmemory (DRAM); asynchronous dynamic random access memory (SDRAM), or anyother desired type of memory device and may be part of or separate fromthe control module 103. The input component 109 and the output component111 may be combined as a single input output card associated with thecontrol module 13. Although the input component 109 of the outputcomponent 111 are illustrated as being built into the control module103, they may be provided as external input output modules attached to acomputer network that plugs into the control module 103.

Additionally control module 103 includes a communication component 113and a power supply 115. The control module 103 processes multiple inputs117 and provides multiple outputs 119. The control module 103 may alsobe coupled to a human machine interface (HMI) 121, such as a digitalcomputer. The HMI, also referred to as man-machine interfaces (MMIs) andgraphical user interface (GUIs) may include use buttons and lights tointeract with the user, text displays, and graphical touch screens.Programming and monitoring software may be installed in a computerconnected to the control module 103 via a communication interface.Programs implementing algorithms to control the various processes wouldtypically be stored in the memory component 107.

Databases may be stored in memory component 107. The databases stored inmemory component 107 may include a compressor loading limit databasethat associates with each gas turbine 3 the compressor loading limitsfor different temperatures Ti at the compressor inlet, fuel air ratio(FAR) at the combustor and guide vane angle θ.

The databases stored in memory component 107 may include emissions limitdatabase that associates emission limits for different Ti, θ, and FARfor each gas turbine 3. The databases stored in memory component 107 mayinclude a flow rate database that associates with each gas turbine 3 thevarious flow rates (Q1, Q2, Q3 etc) for different Ta, Ti, FAR, and θ.Other information in the databases may include compressor flow vs.emission schedules, compressor emission models, data indicating the flowrate coefficient at which aeromechanical stresses occur at the latterstages of the compressor for the specific gas turbine 3 at differentambient temperatures and varying IGV angles.

With reference to FIG. 9, the control module 103 may receive variousinputs from the turbine system including inputs relevant to the controlof the turbine (turbine inputs) 123, and inputs to relevant to thecontrol of the control of the rest of the system (system inputs) 125.Additionally, the control module 103 may receive inputs from the HMI 121(HMI inputs 127). The control module 103 will execute programs based onprogram logic 129 and provide outputs to control the turbine (turbineoutputs 133) and outputs to control the rest of the system (systemoutputs 135).

Turbine Inputs 123 may include: turbine inlet temperatures; turbineexhaust temperature; and unit specific inlet temperature schedules.System inputs 125 may include: extended turndown unit specificcompressor inlet temperature schedules; extraction flow rates;extraction temperatures; inlet temperature schedules; control valvepositions; Safety/Block valve positions, among others. HMI inputs 127may include: selection of a “Normal” Mode—(Outputs—Control valvesclosed, Safety valves closed); or “Turndown” Mode—(Outputs-Controlvalves open permissive, Block valves open permissive).

On a high level, the program logic 129 may be represented as follows:

Exhaust gas extraction Downstream compressor bleed HMI Setting blockvalve 43 positions control valve 31 position Normal Closed ClosedTurndown Permitted to ramp open permitted to ramp openSystem outputs 135 may include instructions to open and close theexhaust gas extraction block valve 43, the overboarding block valve 49,and the safety block valve 54. Additionally system outputs 135 mayinclude instructions to set the positions of Upstream Compressor bleedcontrol valve 29, Downstream compressor bleed control valve 31, Exhaustgas extraction (EGE) control valve 41 and overboarding control valve 51.

FIG. 10 is a flow chart of an illustrative method that may be carriedout by the compressor protection subsystem 5 to reduce the load on a gasturbine 3 from a starting load (Lstart) to a turndown level load (Lend).The operator determines the existing load Lstart (method element 151)and a desired load Lend (method element 153). The control subsystem 11receives data from sensors including ambient temperature (Ta), thetemperature at the compressor inlet (Ti), the IGV vane angle (θ),compressor bleed flow rate Q1, and exhaust gas extraction flow rate Q2(method element 155). The operator may determine a rate of load decreaseΔL/t to take the load from Lstart to L end. An incremental decrease ofthe load ΔL (method element 157) may be determined and the optimal Cm/U,Ti, and θ may be calculated or determined based on the Cm/U restrictionsand emission limits for the particular gas turbine (method element 159).Based on those values, the control subsystem may determine the necessaryflows Q1, Q2, Q5 and Q6 to achieve those conditions, as well as theinput parameters for the attemperation subsystem 55 (method element161). The control subsystem 11 provides instructions to the EGE controlvalve 41 and downstream compressor bleed control valve 31 to achieve thedesired conditions for the reduced load (method element 163). The loadis then reduced by ΔL (method element 165). If Lend has not beenreached, then the process is repeated until the load reaches Lend(method element 167).

FIG. 11 is a flow chart of an illustrative method that may be carriedout by the compressor protection subsystem 5 to increase the load on agas turbine 3 (ramp-up) from a starting load (Lstart) to a ramp up levelload (Lend). The operator determines the existing load Lstart (methodelement 251) and a desired load Lend (method element 253). The controlsubsystem 11 receives data from sensors including ambient temperature(Ta), the temperature at the compressor inlet (Ti), the IGV vane angle(0), compressor bleed flow rate Q1, and exhaust gas extraction flow rateQ2 (method element 255). The operator may determine a rate of loadincrease ΔL/t to take the load from Lstart to L end. An incrementalincrease of the load ΔL (method element 257) may be determined and theoptimal Cm/U, Ti, and θ may be calculated or determined based on theCm/U restrictions and emission limits for the particular gas turbine(method element 259). Based on those values, the control subsystem maydetermine the necessary flows Q1, Q2, Q5 and Q6 to achieve thoseconditions, as well as the input parameters for the attemperationsubsystem 55 (method element 263). The control subsystem 11 providesinstructions to the EGE control valve 41 and downstream compressor bleedcontrol valve 31 to achieve the desired conditions for the increasedload (method element 265). If Lend has not been reached, then theprocess is repeated until the load reaches Lend. Utilizing the methodsillustrated in FIGS. 10 and 11 provide an operator with the flexibilityto control not only the start and end load, but also the rate at whichthe load is changed, while avoiding the aeromechanical stresses on thecompressor 13.

FIG. 12 illustrates an embodiment of a method for turning down a gasturbine 3 to a turndown load while still complying with emissionsstandards that may be performed by the hibernation mode subsystem 7 Theoperator determines the current load (L) (method element 271) and thedesired end load (Lend) (method element 273. The operator can thendetermine an incremental change in the load ΔL (method element 275). Thecontrol subsystem 11 may determine if the flow coefficient at the newload level (Cm/U_(L+ΔL)) would be lower than the flow coefficient at therestricted range (Cm/U_(R)) (method element 277). If the flowcoefficient at the new load level would be less than the restrictedrange flow coefficient, then the control subsystem 11 calculates achange in the compressor inlet temperature ΔT and any change in the IGVvane angle θ that would be required to maintain the flow coefficient ata level higher than the restricted range flow coefficient (methodelement 279). The control subsystem 11 then determines whether the NOxat the new load level would be greater than the applicable maximum NOxemission permissible. Additionally, the control subsystem 11 may alsodetermine if the CO emissions at the new load level would be greaterthan the applicable maximum CO emissions permissible. (Method element281). If the emission levels calculated for the new load exceeds thepermissible levels the control subsystem would then calculate a changein the fuel air ratio necessary for the combustor to operate atemissions levels within the permissible levels (method element 283). Thecontrol subsystem 11 may then change the load to a new level (methodelement 285). The control subsystem 11 may determine if the flowcoefficient at the new load level is less than the flow coefficient atthe restricted level (method element 287). If the flow coefficient atthe new load level is less than the flow coefficient at the restrictedlevel, the control subsystem 11 would instruct the hibernation modesubsystem 7 to adjust the inlet temperature accordingly (method element289). The control subsystem 11 may determine if the NOx emissions levelexceeds the NOx emissions limit imposed on the system. The controlsubsystem 11 may also determine if the CO emissions level exceeds the COemissions limit imposed on the system (method element 291). If theemissions at the new load level exceed the applicable emissions levelcontrol subsystem 11 would instruct the hibernation mode subsystem 7 toadjust the fuel to air ratio at the combustor 15 so that the emissionsare within the permissible level (method element 293). In a combinedcycle gas turbine system the method may additionally include a methodelement for determining the inlet temperature to the heat recovery steamgenerator subsystem 21 for the new load, and if it exceeds a permissibletemperature limit, the control subsystem 11 may instruct the combinedcycle isotherm subsystem 9 to attemperate the temperature of the gas isentering the heat recovery steam generator subsystem 21 so that thetemperature falls within acceptable limits. Utilizing the methodillustrated in FIG. 12 provides an operator with the flexibility tocontrol not only the start and end load, but also the rate at which theload is changed, while avoiding violation of limits imposed by emissionsstandards.

The combination of the compressor protection subsystem 5, thehibernation mode subsystem 7, and in the case of a combined cycle gasturbine system, the combined cycle isotherm subsystem 9, provide a planoperator with the flexibility to operate a gas turbine at very low loadlevels with higher efficiency than conventional systems. Additionally,the combination of subsystems provides the operator with multiple pathsto changing the power output of the gas turbine system 1. By controllingthe combination of the compressor inlet temperature, the fuel to airratio at the combustor 15, and the temperature of gases at the inlet ofthe heat recovery steam generator subsystem 21, the operator is able toimprove the efficiency of a gas turbine 3 and/or the combined cycle at agiven partial load and for a given ambient temperature.

The various embodiments of the gas turbine system 1 provide significantoperating advantages to a gas turbine 3. For example, calculations for arepresentative gas turbine 3 indicate that the turndown limits may bedecreased from a range of between approximately 45% to 60% load to arange of between approximately 10% to 36%, while still maintaining NOxand CO compliance. These load levels may be maintained with a measurableimpact on the BTU/KWh required to operate at the particular load level.

This written description uses examples to disclose the invention,including the best mode, and also to enable any person skilled in theart to practice the invention, including making and using any devices orsystems and performing any incorporated methods. The patentable scope ofthe invention is defined by the claims, and may include other examplesthat occur to those skilled in the art. Such other examples are intendedto be within the scope of the claims if they have structural elementsthat do not differ from the literal language of the claims, or if theyinclude equivalent structural elements with insubstantial differencesfrom the literal languages of the claims.

1. (canceled)
 2. (canceled)
 3. (canceled)
 4. (canceled)
 5. (canceled) 6.(canceled)
 7. (canceled)
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 9. (canceled)
 10. (canceled) 11.(canceled)
 12. (canceled)
 13. A gas turbine system comprising: acompressor; a combustor; a turbine; a compressor protection subsystem; ahibernation mode subsystem; and a control subsystem that controls thecompressor subsystem and the hibernation subsystem.
 14. The gas turbinesystem of claim 13 wherein the compressor protection subsystemcomprises: a compressor bleed line; an exhaust gas extraction line; anda blending assembly coupled to the compressor bleed line and exhaust gasextraction line.
 15. The gas turbine system of claim 14 furthercomprising: a bleed control valve disposed on the compressor bleed line;and a recirculation control valve disposed on the exhaust gas extractionline.
 16. The gas turbine system of claim 14 further comprising: a bleedflow sensor disposed on the compressor bleed line; a recirculation flowsensor disposed on the exhaust gas extraction line.
 17. The gas turbinesystem of claim 14 wherein the blending assembly comprises an eductor.18. The gas turbine system of claim 13 further comprising: anattemperation subsystem coupled to the combustor; and a heat recoverysteam generator subsystem coupled to the attemperation subsystem. 19.The gas turbine system of claim 18 wherein the attemperation subsystemcomprises: a working fluid source; a shaped baffle assembly; and aplurality of fogger injection nozzles coupled to the working fluidsource and disposed in the shaped baffle assembly.
 20. The gas turbinesystem of claim 19 wherein the shaped baffle assembly comprises aplurality of baffles disposed downstream from the fogger injectionnozzles.
 21. A method of extending the turndown range of a gas turbinesystem having a compressor and a combustor comprising: establishingminimum air flow parameters for air flowing through the compressor;conveying turbine exhaust from the turbine to a mixing assembly at afirst flow rate; conveying compressed air from the compressor to themixing assembly at a second flow rate; and controlling the first flowrate and the second flow rate to maintain the compressor airflow abovethe minimum air flow parameters.
 22. The method of claim 21 wherein saidmethod element of conveying turbine exhaust comprises flowing turbineexhaust through an exhaust gas extraction line.
 23. The method of claim21 wherein the method element of conveying compressed air comprisesflowing compressed air from the compressor through a compressor bleedline.
 24. The method of claim 22 wherein the method element ofcontrolling the first flow rate comprises: sensing the first flow ratethrough the exhaust gas extraction line; and controlling a control valveon the exhaust gas extraction line.
 25. The method of claim 23 whereinthe method element of controlling the second flow rate comprises:sensing the second flow rate through the compressor bleed line; andcontrolling a control valve on the compressor bleed line.
 26. The methodof claim 21 wherein the set of minimum relative air flow parameterscomprise a set of airflow coefficients, vane angles, and ambienttemperatures at which aeromechanical stresses occur in the compressor.27. The method of claim 21 further comprising: establishing a set ofmaximum emission parameters; and controlling the first flow rate tomaintain turbine exhaust emissions below the maximum emissionparameters.
 28. The method of claim 27 wherein the maximum emissionparameters are based on an air fuel ratio.
 29. A method for improvingthe efficiency of a combined cycle gas turbine at a partial load, themethod comprising: maintaining an air flow through a compressor at anairflow coefficient for the partial load above a minimum flow ratecoefficient where aeromechanical stresses occur in the compressor;maintaining an air fuel ratio in a combustor where exhaust gas emissioncomponents from the turbine are maintained below a predeterminedcomponent emission level; and maintaining an exhaust gas temperature atan inlet of a heat recirculation steam generator below a predeterminedmaximum inlet temperature.
 30. The method of claim 29, wherein themethod element of maintaining an air flow through the compressorcomprises providing a blend of compressed air from the compressor andexhaust gas from the turbine.
 31. The method of claim 29, wherein themethod element of maintaining the air fuel ratio in a combustorcomprises bleeding compressed air from the compressor to an air inlet ofthe compressor.
 32. The method of claim 29, wherein the method elementof maintaining an exhaust gas temperature comprises flowing exhaustgases through a fogger to attemperate the exhaust gas.
 33. The method ofclaim 29, wherein the method element of maintaining an airflow throughthe compressor comprises controlling a blend ratio of compressed airfrom the compressor and exhaust gas from the turbine using a firstcontrol valve in a compressor bleed line, and a second control valve inan exhaust extraction line.
 34. The method of claim 29 furthercomprising simultaneously controlling the airflow through thecompressor, the air fuel ratio in the combustor, and the exhaust gastemperature at the inlet of the heat recovery steam generator.
 35. Asystem for improving the efficiency of a combined cycle gas turbine at apartial load comprising: a turndown subsystem; a hibernation subsystem;a combined cycle isotherm subsystem; and a control subsystem thatprovides instructions to the turndown subsystem to maintain in airflowthrough a compressor an inner flow coefficient for the partial load upof a minimum flow rate coefficient where aeromechanical stresses occurin the compressor.
 36. The system of claim 35 wherein the controlsubsystem provides instructions to the hibernation subsystem to maintainan air fuel ratio in a combustor so that exhaust gas emission componentsfrom the turbine are maintained below a predetermined component emissionlevel.
 37. The system of claim 35 wherein in the control subsystemprovides instructions to the combined cycle isotherm subsystem tomaintain an exhaust gas temperature at an inlet of the heat recoverysteam generator below a predetermined maximum inlet temperature.